1. Field of the Invention
This invention relates to the controlling gas or liquid slugs in of pipelines and more particularly to controlling gas or liquid slugs in undersea pipelines.
2. Background of the Art
Pipelines are widely used in a variety of industries, allowing a large amount of material to be transported from one place to another. A variety of fluids, such as oil and/or gas, as well as particulate, and other small solids suspended in fluids, are transported cheaply and efficiently using underground pipelines. Pipelines can be subterranean, submarine, on the surface of the earth, and even suspended above the earth. Submarine pipelines especially carry enormous quantities of oil and gas products indispensable to energy-related industries, often under tremendous pressure and at low temperatures and at high flow rates.
Undersea or submarine pipelines typically carry formation fluids from one or more subsea wells. These formation fluids may be, but are not limited to, a gas, a liquid, an emulsion, a slurry and/or a stream of solid particles that has flow characteristics similar to liquid flow. The influent can be a single phase, a two phase or even a three phase admixture. Thus, production fluid can have up to three phases of non-solid materials: hydrocarbons, aqueous solutions, and gas. The production fluid can include solids, some actually exiting the well as solids and other solids precipitating due to changes in temperature, pressure or production fluid composition.
Undersea pipelines, particularly those pipelines running from undersea production wells to loading facilities, commonly referred to as flowlines, can be susceptible to slug formation. Flowlines can stretch for thousands of feet along the subsea floor. In many instances, the flowline can be several thousand feet below the water line, which then requires a vertical leg or riser of similar height to connect the subsea flow line to a surface collection facility. This riser can create a substantial pressure head in the subsea flow line.
During production of a hydrocarbon gas, such as natural gas, condensate entrained in the gas can accumulate at the low points or valleys along the flowline that is situated along an uneven terrain of the subsea floor and/or at the lowermost or base of the riser. The condensate can be a liquid hydrocarbon or water. In any case, the condensate can grow in size to form a liquid slug.
In many instances, the liquid slug can increase in size to an extent that partially or fully occludes the flow bore of the flow line or riser, either of which disrupts the flow of gas to the production facility. Slugs in the flow line can create discontinuities in the pressure gradient across the flow line, which can markedly reduce production flow rates. Moreover, liquid slugs entering in the riser accelerate towards the upper end of the riser due to the increased gas pressure in the partially or fully blocked flow line or riser. Moreover, as should be appreciated, a high-pressure gas or gas slug trails this high-velocity liquid slug. The sudden onrush of these liquid and gas slugs, which can alternate, can pose a severe threat to surface equipment and personnel.
In other instances, the peaks or high points along such a flowline can enable the gas component of the production fluid to collect. In some instances, the gas forms a bubble or bubbles that can grow in size at the high point. As can be appreciated, the gas bubble can to some degree restrict the flow cross-sectional area at the high point, which can lead to an undesirable decrease in flow rates and/or an increase in back pressure. Another problem arises when the gas bubble is released from the high point and flows along the pipeline. The relatively substantial pressure head in the subsea flow line and rise can highly compress this gas slug. As the gas slug moves up the riser toward the surface, the pressure head gradually decreases, which causes the gas to decompress and increase in size. In some cases, gas slugs that are centimeters in diameter in the flow line can expand into diameters of several meters as they approach the surface, which can stress or overwhelm surface equipment.
Conventionally, surge tanks, slug catchers and other devices at the surface facility are used to manage the effects of liquid or gas slugs in the production fluid. Such devices can take up space on the deck of the surface facility. Typically, however, the deck space on an offshore rig or similar facility can be exceedingly limited. Moreover, gas slugs can cause corrosion in the pipe lines as well as make corrosion inhibition difficult. Consequently, it would be desirable in the art of operating pipelines to be able to reduce or eliminate liquid and/or gas slugs without resorting to complex surface equipment that take up surface deck space.
The present invention addresses these and other drawbacks of the prior art.